Throughout the last century electric power plants have been servicing an increasing number of customers. To be able to successfully provide power to these customers, the electric power plants have had to grow. As the power plants grew they became more complex requiring new control systems to monitor their operations.
Older power plants typically utilize several remote operators to control its operations. For instance, auxiliary operators work in the plant operating and monitoring various valves, switches, and gauges of boilers, turbines and generators to produce the electric power. Once the electricity is generated, switchboard operators control the flow of the electricity out of the electric power plant. Power distributors and dispatchers control the flow of the electricity through transmission lines to industrial plants and substations that supply residential and commercial customers with electricity.
In modern electric power plants, the duties of the traditional auxiliary operators, switch operators and distributors and dispatchers are combined in a central control room. The control room operator(s) control an automated control system consisting of a central computer in communication with various peripheral devices that monitor and/or control different parts of the electric power plant.
The following is a general discussion of the operation of an electrical power plant to provide a better understanding of what is being controlled by the conventional automated control system. Large electric power plants producing electricity from any electric generator that is turned by a turbine shaft in response to some energy source. While some electric power plants are operated by hydroelectric or nuclear energy sources, about 63% of the world's electric power and 70% of the electric power produced in the United States is generated from the burning of fossil fuels like coal, oil, or natural gas. The burning of fossil fuels in power plants need to be monitored very closely. Close monitoring is very important when a power plant burns coal.
Mined coal is burned in a combustion chamber at the power plant to produce heat used to convert water in a boiler to steam. This steam is then superheated and introduced to huge steam turbines whereupon it pushes against fanlike blades of the turbine to rotate a shaft. This spinning shaft, in turn, rotates the rotor of an electric generator to produce electricity.
Once the steam has passed through the turbine, it enters a condenser where it passes around pipes carrying cooling water, which absorbs heat from the steam. As the steam cools, it condenses into water which can then be pumped back to the boiler to repeat the process of heating it into steam once again. In many power plants, the water in the condenser pipes that has absorbed the heat from the steam is pumped to a spray pond or cooling tower to be cooled. The cooled water can then be recycled through the condenser or discharged into lakes, rivers, or other water bodies. Conventional control systems can monitor the above steps in the production of electricity from fossil fuels. Eighty-nine percent of the coal mined in the United States is used as the heat source for electric power plants. Unlike petroleum and natural gas, the available supplies of coal that can be economically extracted from the earth are plentiful.
There are four primary types of coal: anthracite, bituminous, subbituminous, and lignite. While all four types of these coals principally contain carbon, hydrogen, nitrogen, oxygen, and sulfur, as well as moisture, the specific amounts of these solid elements and moisture contained in coal varies widely. For example, the highest ranking anthracite coals contain about 98% wt carbon, while the lowest ranking lignite coals (also called “brown coal”) may only contain about 30% wt carbon. At the same time, the amount of moisture may be less than 1% in anthracite and bituminous coals, but 25-30% wt for subbituminous coals like Powder River Basin (“PRB”), and 35-40% wt for North American lignites. For Australia and Russia, these lignite moisture levels may be as high as 50% and 60%, respectively. These high-moisture subbituminous and lignite coals have lower heating values compared with bituminous and anthracite coals because they produce a smaller amount of heat when they are burned. Moreover, high fuel moisture affects all aspects of electric power unit operation including performance and emissions. High fuel moisture results in significantly lower boiler efficiencies and higher unit heat rates than is the case for higher-rank coals. The high moisture content can also lead to problems in areas such as fuel handling, fuel grinding, fan capacity, and high flue gas flow rates.
Bituminous coals therefore have been the most widely used rank of coal for electric power production because of their abundance and relatively high heating values. However, they also contain medium to high levels of sulfur. As a result of increasingly stringent environmental regulations like the Clean Air Act in the U.S., electric power plants have had to install costly scrubber devices upstream of the chimneys of these plants to prevent the sulfur dioxide (“SO2”), nitrous oxides (“NOx”), mercury compounds, and fly ash that result from burning these coals from polluting the air.
Lower-rank coals like subbituminous and lignite coals have gained increasing attention as heat sources for power plants because of their low sulfur content. Burning them as a fuel source can make it easier for power plants to comply with federal and state pollution standards. Also of great relevance is the fact that these subbituminous and lignite coals make up much of the available coal reserves in the western portion of the U.S. However, the higher moisture content of these lower-rank coal types reduces their heat values as a source of heat combustion. Moreover, such higher moisture levels can make such coals more expensive to transport relative to their heat values. They can also cause problems for industry because they break up and become dusty when they lose their moisture, thereby making it difficult to handle and transport them.
While natural gas and fuel oil have almost entirely replaced coal as a domestic heating fuel due to pollution concerns, the rising cost of oil and natural gas has led some factories and commercial buildings to return to coal as a heating source. Because of their higher heating values, bituminous and anthracite coals are generally preferred for these heating applications.
Coal is also the principal ingredient for the production of coke which is used in the manufacture of iron and steel. Bituminous coal is heated to about 2000° F. (1100° C.) in an air-tight oven wherein the lack of oxygen prevents the coal from burning. This high level of heat converts some of the solids into gases, while the remaining hard, foam-like mass of nearly pure carbon is coke. Most coke plants are part of steel mills where the coke is burned with iron ore and limestone to turn the iron ore into pig iron subsequently processed into steel.
Some of the gases produced during carbonization within the coke-making process turn into liquid ammonia and coal tar as they cool. Through further processing, these residual gases can be changed into light oil. Such ammonia, coal tar, and light oil can be used by manufactures to produce drugs, dyes, and fertilizers. The coal tar, itself, can be used for roofing and road surfacing applications.
Some of the gas produced during carbonization in the coke-making process does not become liquid. This “coal gas” burns like natural gas, and can provide heat for the coke making and steel-making processes. The alternative fuels industry has also developed processes for the gasification of coal directly without carbonization. High-energy gas and high-energy liquid fuel substitutes for gasoline and fuel oil result from such gasification processes. Thus, there are many valuable uses for coal besides its intrinsic heat value.
It has previously been recognized within the industry that heating coal reduces its moisture, and therefore enhances the rank and BTU production of the coal by drying the coal. Prior to its combustion in hot water boiler furnaces, drying of the coal can enhance the resulting efficiency of the boiler.
A wide variety of dryer devices have been used within the prior art to dry coal, such as rotary kilns, cascaded whirling bed dryers, elongated slot dryers, hopper dryers, traveling bed dryers, and vibrating fluidized bed dryers. The following dryer devices should give the reader an understanding of types of coal dryers developed thus far: U.S. Pat. No. 5,103,743 issued to Berg, U.S. Pat. No. 4,470,878 issued to Petrovic et al., U.S. Pat. No. 4,617,744 issued to Siddoway et al., U.S. Pat. No. 5,033,208 issued to Ohno et al, U.S. Pat. No. 4,606,793 issued to Petrovic et al., U.S. Pat. No. 4,444,129 issued to Ladt. While all of these different dryer devices may be used to remove moisture from particulate materials like coal, they are relatively complicated in structure, suffer from relative inefficiencies in heat transport, and in some cases are better suited for batch operations rather than continuous operations.
To remedy the above inefficiencies, fluidized-bed dryers or reactors have become well-known within the industry for drying coal. In such dryers, a fluidizing medium is introduced through holes in the bottom of the fluidized bed to separate and levitate the coal particles for improved drying performance. The fluidizing medium may double as a direct heating medium, or else a separate indirect heat source may be located within the fluidized bed reactor. The coal particles are introduced at one end of the reactor, and provide the propulsive means for transporting the particles along the length of the bed in their fluidized state. Thus, fluidized bed reactors are good for a continuous drying process, and provide a greater surface contact between each fluidized particle and the drying medium. See, e.g., U.S. Pat. Nos. 5,537,941 issued to Goldich; 5,546,875 issued to Selle et al.; 5,832,848 issued to Reynoldson et al.; 5,830,246, 5,830,247, and 5,858,035 issued to Dunlop; 5,637,336 issued to Kannenberg et al.; 5,471,955 issued to Dietz; 4,300,291 issued to Heard et al.; and 3,687,431 issued to Parks.
Many of these conventional drying processes, however, have employed very high temperatures and pressures. For example, the Bureau of Mines process is performed at 1500 psig, while the drying process disclosed in U.S. Pat. No. 4,052,168 issued to Koppelman requires pressures of 1000-3000 psi. Similarly, U.S. Pat. No. 2,671,968 issued to Criner teaches the use of updrafted air at 1000° F. Likewise, U.S. Pat. No. 5,145,489 issued to Dunlop discloses a process for simultaneously improving the fuel properties of coal and oil, wherein a reactor maintained at 850-1050° F. is employed. See also U.S. Pat. Nos. 3,434,932 issued to Mansfield (1400-1600° F.); and 4,571,174 issued to Shelton (≦1000° F.).
The use of such very high temperatures for drying or otherwise treating the coal requires enormous energy consumption and other capital and operating costs that can very quickly render the use of lower-ranked coals economically unfeasible. Moreover, higher temperatures for the drying process create another emission stream that needs to be managed. Further complicating this economic equation is the fact that prior art coal drying processes have often relied upon the combustion of fossil fuels like coal, oil, or natural gas to provide the very heat source for improving the heat value of the coal to be dried. See, e.g., U.S. Pat. Nos. 4,533,438 issued to Michael et al.; 4,145,489 issued to Dunlop; 4,324,544 issued to Blake; 4,192,650 issued to Seitzer; 4,444,129 issued to Ladt; and 5,103,743 issued to Berg. In some instances, this combusted fuel source may constitute coal fines separated and recycled within the coal drying process. See, e.g., U.S. Pat. Nos. 5,322,530 issued to Merriam et al; 4,280,418 issued to Erhard; and 4,240,877 issued to Stahlherm et al.
Efforts have therefore been made to develop processes for drying coal using lower temperature requirements. For example, U.S. Pat. No. 3,985,516 issued to Johnson teaches a drying process for low-rank coal using warm inert gas in a fluidized bed within the 400-500° F. range as a drying medium. U.S. Pat. No. 4,810,258 issued to Greene discloses the use of a superheated gaseous drying medium to heat the coal to 300-450° F., although its preferred temperature and pressure is 850° F. and 0.541 psi. See also U.S. Pat. Nos. 4,436,589 and 4,431,585 issued to Petrovic et al. (392° F.); 4,338,160 issued to Dellessard et al. (482-1202° F.); 4,495,710 issued to Ottoson (400-900° F.); 5,527,365 issued to Coleman et al. (302-572° F.); 5,547,549 issued to Fracas (500-600° F.); 5,858,035 issued to Dunlop; and 5,904,741 and 6,162,265 issued to Dunlop et al. (480-600° F.).
Several prior art coal drying processes have used still lower temperatures—albeit, only to dry the coal to a limited extent. For example, U.S. Pat. No. 5,830,247 issued to Dunlop discloses a process for preparing irreversibly dried coal using a first fluidized bed reactor with a fluidized bed density of 20-40 lbs/ft3, wherein coal with a moisture content of 15-30% wt, an oxygen content of 10-20%, and a 0-2-inch particle size is subjected to 150-200° F. for 1-5 minutes to simultaneously comminute and dewater the coal. The coal is then fed to a second fluidized bed reactor in which it is coated with mineral oil and then subjected to a 480-600° F. temperature for 1-5 minutes to further comminute and dehydrate the product. Thus, it is apparent that not only is this process applied to coals having relatively lower moisture contents (i.e., 15-30%), but also the coal particles are only partially dewatered in the first fluidized bed reactor operated at 150-200° F., and the real drying takes place in the second fluidized bed reactor that is operated at the higher 480-600° F. bed temperature.
Likewise, U.S. Pat. No. 6,447,559 issued to Hunt teaches a process for treating coal in an inert atmosphere to increase its rank by heating it initially at 200-250° F. to remove its surface moisture, followed by sequentially progressive heating steps conducted at 400-750° F., 900-1100° F., 1300-1550° F., and 2000-2400° F. to eliminate the water within the pores of the coal particles to produce coal with a moisture content and volatiles content of less than 2% and 15%, respectively, by weight. Again, it is clear that the initial 200-250° F. heating step provides only a limited degree of drying to the coal particles.
One of the problems that can be encountered with the use of fluidized bed reactors to dry coal is the production of large quantities of fines entrapped in the fluidizing medium. Especially at higher bed operating conditions, these fines can spontaneously combust to cause explosions. Therefore, many prior art coal drying processes have resorted to the use of inert fluidizing gases within an air-free fluidized bed environment to prevent combustion. Examples of such inert gas include nitrogen, carbon dioxide, and steam. See, e.g., U.S. Pat. Nos. 3,090,131 issued to Waterman, Jr.; 4,431,485 issued to Petrovic et al.; 4,300,291 and 4,236,318 issued to Heard et al.; 4,292,742 issued to Ekberg; 4,176,011 issued to Knappstein; 5,087,269 issued to Cha et al.; 4,468,288 issued to Galow et al.; 5,327,717 issued to Hauk; 6,447,559 issued to Hunt; and 5,904,741 issued to Dunlop et al. U.S. Pat. No. 5,527,365 issued to Coleman et al. provides a process for drying low-quality carbonaceous fuels like coal in a “mildly reducing environment” achieved through the use of lower alkane inert gases like propane or methane. Still other prior art processes employ a number of heated fluidizing streams maintained at progressively decreasing temperatures as the coal travels through the length of the fluidized bed reactor to ensure adequate cooling of the coal in order to avoid explosions. See, e.g., U.S. Pat. Nos. 4,571,174 issued to Shelton; and 4,493,157 issued to Wicker.
Still another problem previously encountered by the industry when drying coal is its natural tendency to reabsorb water moisture in ambient air conditions over time after the drying process is completed. Therefore, efforts have been made to coat the surface of the dried coal particles with mineral oil or some other hydrocarbon product to form a barrier against adsorption of moisture within the pores of the coal particles. See, e.g., U.S. Pat. Nos. 5,830,246 and 5,858,035 issued to Dunlop; 3,985,516 issued to Johnson; and 4,705,533 and 4,800,015 issued to Simmons.
In order to enhance the process economics of drying low-rank coals, it is known to use waste heat streams as supplemental heat sources to the primary combustion fuel heat source. See U.S. Pat. No. 5,322,530 issued to Merriam et al. This is particularly true within coking coal production wherein the cooling gas heated by the hot coke may be recycled for purposes of heating the drying gas in a heat exchanger. See, e.g., U.S. Pat. Nos. 4,053,364 issued to Poersch; 4,308,102 issued to Wagener et al.; 4,338,160 issued to Dellessard et al.; 4,354,903 issued to Weber et al.; 3,800,427 issued to Kemmetmueller; 4,533,438 issued to Michael et al.; and 4,606,793 and 4,431,485 issued to Petrovic et al. Likewise, flue gases from fluidized bed combustion furnaces have been used as a supplemental heat source for a heat exchanger contained inside the fluidized bed reactor for drying the coal. See, e.g., U.S. Pat. Nos. 5,537,941 issued to Goldich; and 5,327,717 issued to Hauk. U.S. Pat. No. 5,103,743 issued to Berg discloses a method for drying solids like wet coal in a rotary kiln wherein the dried material is gasified to produce hot gases that are then used as the combustion heat source for radiant heaters used to dry the material within the kiln. In U.S. Pat. No. 4,284,476 issued to Wagener et al., stack gas from an associated metallurgical installation is passed through hot coke in a coke production process to cool it, thereby heating the stack gas which is then used to preheat the moist coal feed prior to its conversion into coke.
None of these prior art processes, however, appear to employ a waste heat stream in a coal drying operation as the sole source of heat used to dry the coal. Instead, they merely supplement the primary heat source which remains combustion of a fossil fuel like coal, oil, or natural gas. In part, this may be due to the relatively high drying temperatures used within these prior art dryers and associated processes. Thus, the process economics for drying the coal products, including low-rank coals, continues to be limited by the need to burn fossil fuels in order to dry a fossil fuel (i.e., coal) to improve its heat value for firing a boiler in a process plant (e.g., an electric power plant).
Moreover, many prior art fluidized bed dryers can suffer from plugging as the larger and denser coal particles settle to the bottom of the dryer, and make it more difficult to fluidize the rest of the particles. Condensation within the upper region of the dryer can also cause the fluidized particles to agglomerate and fall to the bottom of the dryer bed, thereby contributing to this plugging problem. For this reason, many of the prior art fluidized dryer designs seem to be vertical in orientation or feature multiple, cascading dryers with fluidizing medium inlet jets directed to creating improved fluidizing patterns for the coal particles contained within the dryer.
The operation of a dryer unit such as a fluidized bed dryer at lower temperatures below 300° F. would be desirable, and could obviate the need to suppress spontaneous combustions of the coal particles within the dryer. Moreover, incorporation of mechanical means within the fluidized bed dryer for physically separating and removing larger, denser coal particles from the dryer bed region and eliminating condensation around the fluidized particles would eliminate potential plugging problems that can otherwise cause dryer inefficiencies. Perhaps more importantly for the present invention, none of the prior fluidized bed dryers discuss, disclose, teach or suggest a control system that controls the heated waste streams entering and/or leaving the fluidized bed dryer.
Controlling the drying process of coal prior to its introduction to the boiler furnace should improve the process economics of using low-rank coals like subbituminous and lignite coal. Such low-rank coal sources could suddenly become viable fuel sources for power plants compared with the more traditionally used bituminous and anthracite coals. The economical use of lower-sulfur subbitumionous and lignite coals, in addition to removal of undesirable elements found within the coal that causes pollution, would also be greatly beneficial to the environment.